1. Field of the Invention
The present invention relates generally to a telemetry system for transmitting data from a downhole drilling assembly to the surface of a well during drilling operations. More particularly, the present invention relates generally to methods for transmitting downhole measurements to the surface of the well through separate channels or media.
2. Description of the Related Art
The recovery of subterranean hydrocarbons, such as oil and gas, usually requires drilling boreholes thousands of feet deep. In addition to an oil rig on the surface, drilling string tubing extends downward through the borehole to hydrocarbon formations. The borehole may also be drilled to include horizontal, or lateral bores. As a result, modern petroleum drilling operations demand a great quantity of information relating to parameters and conditions downhole. Such information typically includes characteristics of the earth formations traversed by the wellbore, in addition to data relating to the size and configuration of the borehole itself. The collection of information relating to conditions downhole, which commonly is referred to as “logging,” can be performed by several methods. Oil well logging has been known in the industry for many years as a technique for providing information to a driller regarding the particular earth formation being drilled. In conventional oil well wireline logging, a probe or “sonde” housing formation sensors is lowered into the borehole after some or all of the well has been drilled, and is used to determine certain characteristics of the formations traversed by the borehole. The sonde is supported by an electrically conductive wireline, which attaches to the sonde at the upper end. Power is transmitted to the sensors and instrumentation in the sonde through the conductive wireline. Similarly, the instrumentation in the sonde communicates information to the surface by electrical signals transmitted through the wireline.
One of the problems with obtaining downhole measurements via wireline is that the drilling assembly must be removed or “tripped” from the drilled borehole before the desired borehole information can be obtained. This can be both time-consuming and extremely costly, especially in situations where a substantial portion of the well has been drilled. In this situation, thousands of feet of tubing may need to be removed and stacked on the platform (if offshore). Typically, drilling rigs are rented by the day at a substantial cost. Consequently, the cost of drilling a well is directly proportional to the time required to complete the drilling process. Removing thousands of feet of tubing to insert a wireline logging tool can be an expensive proposition. In addition to the desire to get data during drilling to avoid the complexities of obtaining downhole measurements by stopping drilling, data obtained while drilling has intrinsic value for safety, drilling decisions (such as where to set casing, and remaining on target within a formation), and quality control.
As a result, there has been an increased emphasis on the collection of data during the drilling process. By collecting and processing data during the drilling process, without the necessity of removing or tripping the drilling assembly to insert a wireline logging tool, the driller can make accurate modifications or corrections, as necessary, to optimize performance while minimizing down time. Techniques for measuring conditions downhole and the movement and location of the drilling assembly, contemporaneously with the drilling of the well, have come to be known as “measurement-while-drilling” techniques, or “MWD.” Similar techniques, concentrating more on the measurement of formation parameters, commonly have been referred to as “logging while drilling” techniques, or “LWD.” While distinctions between MWD and LWD may exist, the terms MWD and LWD often are used interchangeably. For the purposes of this disclosure, the term MWD will be used with the understanding that this term encompasses both the collection of formation parameters and the collection of information relating to the movement and position of the drilling assembly.
Drilling oil and gas wells is carried out by means of a string of drill pipes connected together so as to form a drill string. Connected to the lower end of the drill string is a drill bit. The bit is rotated and drilling accomplished by either rotating the drill string, or by use of a downhole motor near the drill bit, or by both methods. Drilling fluid, termed mud, is pumped down through the drill string at high pressures and volumes (such as 3000 p.s.i. at flow rates of up to 1400 gallons per minute) to emerge through nozzles or jets in the drill bit. The mud then travels back up the hole via the annulus formed between the exterior of the drill string and the wall of the borehole. On the surface, the drilling mud is cleaned and then recirculated. The drilling mud is used to cool and lubricate the drill bit, to carry cuttings from the base of the bore to the surface, and to balance the hydrostatic pressure in the rock formations.
When oil wells or other boreholes are being drilled, it is frequently necessary or desirable to determine the direction and inclination of the drill bit and downhole motor so that the assembly can be steered in the correct direction. Additionally, information may be required concerning the nature of the strata being drilled, such as the formation's resistivity, porosity, density and its measure of gamma radiation. It is also frequently desirable to know other downhole parameters. Examples of this are the temperature and the pressure at the base of the borehole. Once the data is gathered at the bottom of the borehole, it is typically transmitted to the surface for use and analysis by the driller.
In MWD systems sensors or transducers typically are located at the lower end of the drill string which, while drilling is in progress, continuously or intermittently monitor predetermined drilling parameters and formation data and transmit the information to a surface detector by some form of telemetry. Typically, the downhole sensors employed in MWD applications are positioned in a cylindrical drill collar that is positioned close to the drill bit. The MWD system then employs a system of telemetry in which the data acquired by the sensors is transmitted to a receiver located on the surface.
There are a number of telemetry systems in the prior art which seek to transmit information regarding downhole parameters (downhole telemetry data) up to the surface without requiring the use of a wireline tool. Linking downhole instrumentation to the surface with wiring has proven exceedingly expensive and unreliable due to operational constraints such as making up pipe joints (requiring a separate connection to the link for each joint), operational hazards, and the corrosive fluids and high ambient temperatures often found in the well.
Electromagnetic radiation has been utilized to telemeter data from downhole to the surface (and vice-versa). In these systems, a current is either induced on the drill string from a downhole transmitter, or an electrical potential is impressed across an insulated gap in a downhole portion of the drill string. Information is transmitted from downhole by modulating this current or voltage, and is detected at the surface with electric field and or magnetic field sensors. In a preferred embodiment, information is transmitted by phase shifting a carrier wave among a number of discrete phase states. Although the drill pipe acts as part of the conductive path, system losses are almost always dominated by conduction losses within the earth, which also carries the electromagnetic radiation. These systems work well in regions where the earth's conductivity between the telemetry transmitter and the earth's surface is consistently low. As a rule of thumb, the conductive losses through a homogeneous section of the earth vary as   ⅇ      -                                        2            ⁢                                                   ⁢                          π              ⁢                                                           ·              f                        ⁢                                                   ⁢            μ            ⁢                                                   ⁢            σ                    2                ⁢        z            where f is the frequency of the radiation in Hz, μ is the magnetic permeability of the medium through which the field propagates (typically, μ=4·π·10−7 henrys/meter), σ is the conductivity of the medium (typically, 0.0005<σ<10 mhos/meter and varies considerably between the transmitter and the earth's surface). If such a system is to be used in the presence of high conductivities, even for a portion of the telemetry path, it is necessary to restrict f to very low values, on the order of 1 Hz, in order to reduce signal loss to an acceptable level. Where the conductivity is favorable, it is possible to exceed mud pulse telemetry rates with these systems, and it may be possible to rival the rates achievable with acoustic telemetry systems. Such low conductivity regions constitute a small segment of the wells needing telemetry while drilling. Representative examples of electromagnetic telemetry systems may be found in U.S. Pat. Nos. 4,302,757, 4,525,715, and 4,691,203. U.S. Pat. Nos. 6,075,462 and 6,160,492, the disclosures of which are incorporated herein by reference, discuss electromagnetic telemetry in general and a preferred electromagnetic telemetry device in detail.
More common is the practice of transmitting data using pressure waves in drilling fluids such as drilling mud, or mud pulse/mud siren telemetry. The mud pulse system of telemetry creates acoustic and pressure signals in the drilling fluid that is circulated under pressure through the drill string during drilling operations. The information that is acquired by the downhole sensors is transmitted by suitably timing the formation of pressure pulses in the mud stream. The information is received and decoded by a pressure transducer and computer at the surface.
In a mud pressure pulse system, the drilling mud pressure in the drill string is modulated by means of a valve and control mechanism, generally termed a pulser or mud pulser. The pulser is usually mounted in a specially adapted drill collar positioned above the drill bit. The generated pressure pulse travels up the mud column inside the drill string at the velocity of sound in the mud. Depending on the type of drilling fluid used, the velocity may vary between approximately 3000 and 5000 feet per second. The rate of transmission of data, however, is relatively slow due to pulse spreading, distortion, attenuation, modulation rate limitations, and other disruptive forces, such as the ambient noise in the transmission channel. A typical pulse rate is on the order of a pulse per second (1 Hz). The preferred embodiment uses pulse position modulation to transmit data. In pulse position modulation, all of the pulses have a fixed width, and the interval between pulses is proportional to the data value transmitted. The primary method of increasing the data rate of the transmitted signal is to increase the mean frequency f of the pulses. As the frequency f of the pulses increases, however, it becomes more and more difficult to distinguish between adjacent pulses because the resolution period is too short. The problem is that the period T for each individual pulse has decreased proportionately (T=1/f). The resolution therefore decreases, causing problems with detection of the adjacent pulses at the surface. A more important problem than inter-symbol interference caused by decreased period is the fact that the attenuation of mud pulses increases significantly with frequency so that as one attempts to increase the data rate, less signal is available at the surface. A situation rapidly develops in which the signal cannot be detected as one attempts to increase the data rate. Representative examples of mud pulse telemetry systems may be found in U.S. Pat. Nos. 3,949,354, 3,958,217, 4,216,536, 4,401,134, and 4,515,225. U.S. Pat. No. 5,586,084, the disclosure of which is incorporated herein by reference, discusses mud pulsers in general and a preferred mud pulser in detail.
Mud pressure pulses can be generated by opening and closing a valve near the bottom of the drill string so as to momentarily restrict the mud flow. In a number of known MWD tools, a “negative” pressure pulse is created in the fluid by temporarily opening a valve in the drill collar so that some of the drilling fluid will bypass the bit, the open valve allowing direct communication between the high pressure fluid inside the drill string and the fluid at lower pressure returning to the surface via the exterior of the string. Alternatively, a “positive” pressure pulse can be created by temporarily restricting the downward flow of drilling fluid by partially blocking the fluid path in the drill string.
Both the positive and negative mud pulse systems typically generate base band signals. In an attempt to increase the data rate and reliability of the mud pulse signal, other techniques also have been developed as an alternative to the positive or negative pressure pulses generated. One early system is that disclosed in U.S. Pat. No. 3,309,656, which used a downhole pressure pulse generator or modulator to transmit modulated signals, carrying encoded data, at acoustic frequencies to the surface through the drilling fluid or drilling mud in the drill string. In this and similar types of systems, the downhole electrical components are powered by a downhole turbine generator unit, usually located downstream of the modulator unit, that is driven by the flow of drilling fluid. These types of devices typically are referred to as mud sirens. Other examples of such devices may be found in U.S. Pat. Nos. 3,792,429, 4,785,300 and Re. 29,734. U.S. Pat. No. 5,586,083, the disclosure of which is incorporated herein by reference, discusses mud sirens in general and a preferred mud siren in detail.
Telemetry utilizing acoustic transmitters in the pipe string has emerged as a potential method to increase the speed and reliability of data transmission from downhole to the surface. When actuated by a signal such as a voltage potential from a sensor, an acoustic transmitter mechanically mounted on the tubing imparts a stress wave or acoustic pulse onto the tubing string. Because metal pipe propagates stress waves more effectively than drilling fluids, acoustic transmitters used in this configuration have been shown to transmit data in excess of 10 BPS (bits per second). Furthermore, such acoustic transmitters can be used during all aspects of well site development regardless of whether drilling fluids are present. Examples of acoustic transmitters include the disclosures of U.S. Pat. Nos. 5,703,836, 5,222,049, and 4,992,997. U.S. Pat. No. 6,137,747, the disclosure of which is incorporated herein by reference, discusses acoustic transmitters in general and a preferred acoustic transmitter for transmission through the drill string in detail. While acoustic telemetry through the drill string has been a project for many years, commercial success, even during non-drilling conditions, has only relatively recently been obtained. Additionally, while several patents and publications provide suggestions for such telemetry while drilling (see for example U.S. Pat. No. 3,588,804 to Fort, U.S. Pat. No. 4,320,473 to Smither and Vela, and SPE paper 8340 from 1979 authored by Squire and Whitehouse and titled “A new approach to drill-string acoustic telemetry”), a full commercially successful embodiment providing commercially desirable bandwidths has not yet been marketed. The presence of less reliable and at best narrower bandwidth options for acoustic telemetry through the drill string support the need for the method of the present application to address how best to optimize use of current and pending developments in this area.